System for production of a hydrocarbonaceous fluid

ABSTRACT

Embodiments of the disclosure pertain to a system for production of a hydrocarbonaceous fluid, the system having a tubing string deployed within a wellbore; a first pump system having a pump assembly operably engaged with a motor; and a control system operably engaged with the first pump system. The pump assembly includes a housing with a stator and rotor disposed therein. The first pump system is operable to aid in production of the hydrocarbonaceous fluid from the wellbore to a production facility.

CROSS-REFERENCE TO RELATED APPLICATIONS AND INCORPORATION BY REFERENCE

This application is a continuation of U.S. Non-Provisional patentapplication Ser. No. 14,433,970, filed Apr. 7, 2015, which is a §371national application of PCT Application No. PCT/GB2013/052773, filedOct. 24, 2013, which claims foreign priority to GB Application No. GB1219547.5, filed on Oct. 31, 2012. The disclosure of each application ishereby incorporated herein by reference in its entirety for allpurposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

BACKGROUND

Field of the Disclosure

The present disclosure relates to the field of hydrocarbon exploration.More specifically, embodiments disclosed herein pertain to a method ofpumping hydrocarbons that finds particular application for use withheavy and extra heavy fluids commonly found within the field ofhydrocarbon exploration.

Background of the Disclosure

The definition of heavy and extra heavy oil is not strictly definedwithin the art. For the purposes of the following discussion the termheavy oil may be used to refer to a hydrocarbon fluid mixtures oremulsions with a viscosity between 1,000 cP (centi-Poise) and 20,000 cPwhile the term extra heavy oil may be used to refer to a hydrocarbonfluid mixtures or emulsions with a viscosity greater than 20,000 cP.

Horizontal drilling and horizontal wells have transformed theproductivity of many conventional oil & gas wells by providingconsiderably greater reservoir inflow capability compared to verticaland deviated wells. Generally, horizontal wells are formed by initiallydrilling a vertical section to a specified depth. The high angle orhorizontal section of the well is then drilled at a depth to maximizethe contact between the wellbore and the reservoir. Increasing thecontact between the wellbore and the reservoir can provide greaterinflow potential. Long horizontal sections two kilometers or more areknown in the art.

The above horizontal drilling techniques have been successfully employedby those skilled in the art in order to extract hydrocarbons. However,when deployed with heavy oil and extra heavy oil reservoirs the resultshave been poor due to the effects of friction loss and pseudo-plastic“gelling” of the reservoir fluids within the wellbore. In a longhorizontal wellbore employed with a heavy oil reservoir, up to 90% ofthe theoretical inflow potential may be lost due to friction loss andpseudo-plastic “gelling”.

In order to improve the production of heavy oils some operators haveexperimented with employing larger diameter horizontal wellbores (e.g.12¼″ (311.15 mm) bore cased with 9⅝″ (234.32 mm) casing instead of thenormal 8½″ (215.90 mm) bore cased with 7″ (177.80 mm) casing). However,such wells are technically challenging, very expensive to drill and caseand have only had limited beneficial effect. As a result, longhorizontal wells are not proved effective in heavy and extra-heavy oilfields.

A second solution to this problem is for operators to drill multipleshort horizontal wells, perhaps 100 meters in length. These wells may bedrilled in a “crow's foot” or “herring bone” configuration or equivalentarray structure to reduce the problems associated with a long wellbore.However, as appreciated by those skilled in the art, the drilling ofmultiple wells significantly increases the production costs for heavyoils and extra-heavy oils.

It is frequently required when exploring for hydrocarbons to provideartificial lift to the production fluid e.g. when extractinghydrocarbons from an oil bed it may be required to employ the assistanceof a pump when the pressure of the hydrocarbon deposit is insufficientto bring the hydrocarbons to the surface. Some examples of such pumpsknown in the art include Electric Submersible Pumps (ESP), ProgressingCavity Pumps (PCP) or positive displacement pumps; centrifugal pumps;single helix pumps; and dual-helix axial or compressor pumps.

Including a pump system with the above described wellbore arrangementsmay help heavy oil and extra-heavy oil production for some reservoirs.However, other factors exists which still limit the levels of heavy oiland extra-heavy oil that can be extracted. By way of example, thepreferred pump for such production is an Electric Submersible Pumps(ESP).

When an ESP is employed with within a wellbore it is required to bedeployed at a lesser depth (i.e., nearer the surface of the wellbore)than the wellbore perforations in order to allow the production fluid tocool the motor and pump modules as it passes over the outer surface ofESP. This configuration has an inherent benefit for the production ofheavy oil and extra-heavy oil in that heat is transferred from the ESPto the production fluid as it passes into the tubing string thus makingit less viscous and thus easier to pump to the surface. The benefit ofheating a heavy oil with an ESP is known in the art, see for example USpatent numbers U.S. Pat. No. 8,037,936; U.S. Pat. No. 6,318,467 and U.S.Pat. No. 6,564,874.

However with this arrangement the high viscosity of the heavy oil in thereservoir itself is found to cause preferential production from the“heel” end of the reservoir with little or no production from the ‘toe’end. As reservoir fluid viscosity increases, this effect becomes moresevere. Typically, only the first 50 meters of a reservoir willcontribute to the production process with such an arrangement. In thesecircumstances operators are again forced to consider multiple wells andthe associated increases in the production costs.

In addition, although ESP systems have been demonstrated to be arecapable of pumping fluids with viscosities up to around 1,500 cP to2,000 cP, the performance of an ESP is greatly reduced when operatingwith a fluid at such viscosities. The ESPs known in the art are simplyunable to pump fluids with viscosities greater than 2,000 cP and so arenot suitable for use with extra-heavy oils or even many heavy oils.

It is recognized that in accordance with the disclosure considerableadvantage is to be gained in a completion design that is capable ofproducing heavy and extra heavy oil from wells and in particular longhorizontal or high angle wells.

SUMMARY

Embodiments of the disclosure pertain to a system for production of ahydrocarbonaceous fluid that may include a tubing string deployed withina wellbore; a first pump system having a pump assembly operably engagedwith a motor, and a control system operably engaged with the first pumpsystem; wherein the first pump system may be operable to aid inproduction of a hydrocarbonaceous fluid from the wellbore to aproduction facility. The hydrocarbonaceous fluid may have a viscosity ofgreater than 1,000 cP.

The pump assembly may include a stator with an inner stator surfacehaving one or more stator vanes thereon. The assembly may include arotor having an external stator surface configured with an one or morerotor vanes thereon. The assembly may include a housing having thestator and the rotor disposed therein. A radial gap may be provided orotherwise exist between the one or more stator vanes and the one or morerotor vanes along a length of the pump assembly. A radial length of theone or more rotor vanes may be greater than a radial length of the oneor more stator vanes. A thickness of the one or more stator vanes may begreater than a thickness of the one or more rotor vanes.

There may be one or more stator channels on the inner stator surface.The one or more stator channels may have a constant inner diameter.There may be one or more rotor channels on the rotor outer surface. Therotor channels may have a constant outer diameter. The first pump systemmay be in fluid communication with the tubing string.

The first pump system may include a cooling shroud that depends from thepump assembly so as to define a flow path that requires the hydrocarbonfluid to pass over the motor before entering the pump assembly.

There may be a protector seal module located between the pump assemblyand the motor. The control system may be operable to change a set ofoperating parameters of the pump assembly of so as to optimize thehydrocarbon fluid production from the wellbore. There may be anoperating frequency as one of the set of operating parameters. Thecontrol system may be operable to control a choke. The system mayinclude a second pump system like that of the first pump system. Thesecond pump system may also be in fluid communication with the tubingstring. In aspects, the hydrocarbonaceous fluid may have a viscosity ofgreater than 20,000 cP. The first pump system may be operable andlocated 75% to 95% of the way along a length of the wellbore. The rotorchannels and stator channels may all be of the same lengths andcross-sectional area.

The pump assembly may further include an inlet; an outlet; and twobearings separated along an longitudinal axis of the pump assembly, oneof which being proximate to the inlet, and the other being proximate tothe outlet.

Other embodiments of the disclosure pertain to a system for productionof a hydrocarbonaceous fluid that may include a tubing string deployedwithin a wellbore; a first pump system having a pump assembly operablyengaged with a motor; and a control system operably engaged with thefirst pump system. The first pump system may be operable to aid inproduction of a hydrocarbonaceous fluid from the wellbore to aproduction facility. The hydrocarbonaceous fluid may have a viscosity ofgreater than 1,000 cP.

The pump assembly may include a stator having an inner stator surfaceconfigured with an at least one stator vane thereon; a rotor having anexternal stator surface configured with an one or more rotor vanesthereon; and a housing having the stator and the rotor disposed therein.There may be a radial gap provided or otherwise existing between the oneor more stator vanes and the one or more rotor vanes along a length ofthe pump assembly. A radial length of the one or more rotor vanes may begreater than a radial length of the one or more stator vanes. Athickness of the one or more stator vanes may be greater than athickness of the one or more rotor vanes.

Stator channels on the inner stator surface may include a constant innerdiameter. Rotor channels on the rotor outer surface may include aconstant outer diameter. The first pump system may be in fluidcommunication with the tubing string.

The first pump system may include a cooling shroud that depends from thepump assembly so as to define a flow path. This may result in therequirement that hydrocarbon fluid should pass over the motor beforeentering the pump assembly.

The system may include a protector seal module is located between thepump assembly and the motor.

The control system may be operable to change a set of operatingparameters of the pump assembly of so as to optimize the hydrocarbonfluid production from the wellbore. An operating frequency may be one ofthe set of operating parameters. The control system may be operable tocontrol a choke.

The system may include a second pump system like that of the first pumpsystem. The second pump system may also be in fluid communication withthe tubing string.

In aspects, the hydrocarbonaceous fluid may have a viscosity of greaterthan 20,000 cP. The first pump system may be located 75% to 95% of theway along a length of the wellbore.

The rotor channels and stator channels may be all of the same lengthsand cross-sectional area.

The pump assembly may further include an inlet; an outlet; two bearingsseparated along an longitudinal axis of the pump assembly, one of whichbeing proximate to the inlet, and the other being proximate to theoutlet.

These and other embodiments, features and advantages will be apparent inthe following detailed description and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A full understanding of embodiments disclosed herein is obtained fromthe detailed description of the disclosure presented herein below, andthe accompanying drawings, which are given by way of illustration onlyand are not intended to be limitative of the present embodiments, andwherein:

FIG. 1 shows a section view of a horizontal reservoir with a single pumphydrocarbon completion in accordance with embodiments of the disclosure;

FIG. 2 presents a schematic representation of the pump system of FIG. 1in accordance with embodiments of the disclosure;

FIG. 3 presents a cross-sectional assembled view of a pump assembly ofthe pump system of FIG. 2 in accordance with embodiments of thedisclosure;

FIG. 4 presents a section view of the horizontal section of a horizontalwell showing the fluid flow paths and heat transfer paths in accordancewith embodiments of the disclosure;

FIG. 5 presents a section view a horizontal reservoir with a multiplepump hydrocarbon completion in accordance with embodiments of thedisclosure;

FIG. 6 presents a section view of an electro-hydraulic diverter employedwithin the multiple pump hydrocarbon completion of FIG. 5 in accordancewith embodiments of the disclosure; and

FIG. 7 presents a section view of a horizontal reservoir with analternative multiple pump hydrocarbon completion in accordance withembodiments of the disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure are described in detail withreference to the accompanying Figures. In the following discussion andin the claims, the terms “including” and “comprising” are used in anopen-ended fashion, such as to mean, for example, “including, but notlimited to . . . ”. While the disclosure may be described with referenceto relevant apparatuses, systems, and methods, it should be understoodthat the disclosure is not limited to the specific embodiments shown ordescribed. Rather, one skilled in the art will appreciate that a varietyof configurations may be implemented in accordance with embodimentsherein.

The terms “upper”, “lower”, “downward” and “upward” are relative termsused herein that may be indicative of directions in a wellbore, with“upper” and equivalents referring to the direction along the wellboretowards the surface, and “lower” and equivalents referring to thedirection towards the bottom hole. It will be appreciated thatembodiments of the disclosure may have application to deviated andlateral wellbores.

A hydrocarbon completion in accordance with an embodiment of the presentdisclosure, and generally depicted by reference numeral 1, will now bedescribed with reference to FIGS. 1 to 4. The completion design 1 can beseen deployed with a substantially horizontal reservoir 2 comprisingheavy and or extra heavy oil 3.

The hydrocarbon completion 1 can be seen to comprise a well 4 formedfrom a casing 5, which is cemented into a wellbore 6. The casing 5 maycomprise perforated casing or screen installed casing as is known tothose skilled in the art. The horizontal section of the well 4 b is at adepth to maximize the contact between the wellbore 6 and the heavy orextra heavy oil 3 within the reservoir 2.

A tubing string 7 is supported via a tubing hanger 8 located at thesurface 9. The tubing string defines an annulus 10 with the surroundingwellbore. Also located at the surface 9 is a wellhead 11 comprising aproduction choke 12, a control system 13 and a production facility 14.

A pump system 15, which is connected to tubing string 7, is locatedwithin the horizontal section of the well 4 b. As described in furtherdetail below, it is preferable for as many well perforations 16 to liebetween the pump system 15 and the surface 9 i.e. the pump system islocated further into the well 4 than one or more of the wellperforations 16. Preferably, the pump system 15 is located 75% to 95% ofthe way along the horizontal section of the well 4 b.

The pump system 15 is employed to artificially lift the production fluid17 up the tubing string 7 and through the wellhead 11, where the fluid17 is then controlled and distributed to the production facility 14. Thepump system 15 is controlled at surface 9 by the control system 13connected to the pump system 15 by a down-hole electrical cable 18.

Further detail of the pump system 15 will now be described withreference to FIGS. 2 and 3. From FIG. 2 the pump system 15 can be seento comprise a motor 19 and a pump assembly 20. Preferably a protectorseal module 21 is located between the motor 19 and the pump assembly 20.A cooling shroud 22 depends from the pump assembly 20 so as to define aflow path that requires the heavy oil 3 to pass over the motor 19 beforeentering the pump assembly 20.

The pump assembly 20, as shown schematically in FIG. 3, is preferably apump assembly of the type described by the inventor within PCTpublication number WO 2012/013973. Here the pump assembly 20 can be seento comprise a rotor 23 which is surrounded by an annular stator 24 thatis arranged to be coaxial with, and extend around, the rotor 23. Therotor 23 is externally screw-threaded in a right-handed sense by theprovision of three rotor vanes 25 located on its external surface. Thestator 24 is correspondingly internally screw-threaded in a left-handedsense through the provision of three stator vanes 26 located on itsinternal surface. The rotor vanes 25 and the stator vanes 26 arethreaded so as to exhibit equal pitch and have radial heights such thatthey approach each other sufficiently closely so as to provide rotorchannels 27 and stator channels 28 within which a fluid can be retainedfor longitudinal movement upon rotation of the rotor 23. In thepresently described embodiment the rotor channels 27 and stator channels28 are all of the same length and cross sectional area.

The pump assembly 20 can be seen to further comprise a cylindricalhousing 29 within which the remaining components are located. The rotor23 is connected to the motor 19 by means of a central shaft 30 such thatoperation of the motor 19 induces relative rotation between the rotor 23and the stator 24.

An inlet 31 and an outlet 32 of the pump assembly 20 are defined by thelocation of two bearings 33 separated along the longitudinal axis of thedevice. The bearings 33 assist in securing the rotor 23 and the stator24 within the cylindrical housing 29 while reducing the effects ofmechanical vibration thereon during normal operation. The inlet 31 andoutlet 32 are obviously determined by the orientation in which the pumpassembly 20 is operated i.e. with reference to FIG. 3 the fluid flow issubstantially along the positive z-axis but can be reversed depending onwhether the rotation of the rotor 23 is clockwise or anticlockwise.

By setting:

-   -   1) the size of a radial gap between the rotor vanes 25 and the        stator vanes 26;    -   2) the relative heights of the rotor vanes 25 and the stator        vanes 26; and    -   3) the relative thicknesses of rotor vanes 25 and the stator        vanes 26, the pump assembly 20 provides an efficient and robust        means for pumping high viscosity and/or multiphase fluids.        Significantly, the pump assembly design allows it to be run at        operating temperature as high as 400° C., almost twice the        highest operating temperatures achievable with an ESP. This high        operating temperature makes the pump assembly 20 particularly        suitable for use within the presently described completion 1, as        will be described in further detail below.

The operation of the completion 1 of FIG. 1 will now be described withreference to FIG. 4 which shows a section view of the horizontal section4 b of a horizontal well showing both fluid flow paths (as generallyindicated by the direction of the arrows) and heat transfer paths (asgenerally indicated by the size of the arrow heads, larger arrow headsrepresents a higher fluid temperature at the location of the arrow).

In the first instance the heavy oil 3 contained within the reservoir 2is at a typical temperature of ˜55° C. and viscosity of ˜5,000 cP. Theheavy oil 3 flows from the reservoir 2 into the wellbore 6, asrepresented by arrows 34.

When the pump system 15 is activated heavy oil 3 is pumped into thetubing string 7, as described above, so as to produce a production fluid17 that has a direction of flow towards the surface 9, as indicated byarrows 35. The pump assembly 20 is run at a fluid discharge temperatureof ˜300° C., and as will be described below, since a pre-warmed fluidflows past the motor 19 in a turbulent flow a significant enhancement ofthe motor 19 cooling process is observed. The produced fluid then passesthrough the pump assembly 20 resulting in the pressure beingconsiderably increased (potential energy). Therefore, by the time theheavy oil 3 has entered the shroud 22, passed over the motor 19 and theprotector seal module 21 and through the pump assembly 20 into thetubing string 7 it has been heated to a temperature of ˜150° C. and hasa viscosity of ˜50 cP. It is obviously significantly easier for the pumpsystem 15 to pump the production fluid 17 towards the surface 9 when itexhibits a significantly lower viscosity as it flows through the tubingstring 7.

It will be appreciated by those skilled in the art that a productionfluid 17 having a temperature of ˜150° C. cannot be easily handled by anoperator at the surface 9. Indeed in a normal production completion thistemperature would be regarded as unacceptable since it is desirable forthe temperature of the production fluid 17 to be below 100° C. at thesurface 9 so as to avoid the problematic effects of flash evaporation ofwater from the production fluid 17 and any consequent salt deposition.

As can be seen from FIG. 4, the design of completion 1 is such that theproduction fluid 17 in the tubing string 7 cools as it is pumped towardsthe surface 9 by transferring heat to the surrounding heavy oil 3located in the annulus 10 of the wellbore 6 and the reservoir 2.

In the presently described embodiment, the production fluid 17 coolsfrom ˜150° C. at it leaves the pump assembly to ˜90° C. by the time itreaches the surface 9. The viscosity of the production fluid 17 thuscorrespondingly increases from ˜50 cP to ˜250 cP.

The production fluid 17 in the tubing string 7 however simultaneouslyacts as a counter current heat exchanger with the annulus fluid flow, asindicated by arrows 36. This heating of the fresh reservoir productioncommences immediately on the oil contacting the hot tubing string 7.This heating is continuous as the oil flows alongside the tubing string7 (but counter to the flow within the tubing string 7). As a result, theheavy oil 3 is heated from the reservoir temperature of ˜55° C. to ˜100°C. before it enters the pump system 15. The viscosity of the heavy oil 3within the annulus fluid flow 36 thus falls from ˜5,000 cP to ˜200 cP asa result of this counter current heat exchange mechanism.

The pump system 15 can be employed so as to optimize the operation ofthe completion 1, as and when required. There are two available optionsfor this which can be employed independently or in conjunction with eachother.

The first option involves employing the control system 13 to change theoperating frequency of the pump assembly 20. By changing the operatingfrequency of the pump assembly 20 the operating temperature andtemperature rise created within the pump system 15 can be adjusted. Ingeneral, if the completion 1 is running too hot then the operatingfrequency of the pump assembly 20 is lowered. Similarly, if thecompletion 1 is running too cold then the operating frequency of thepump assembly 20 is increased.

The second option involves adjusting the choke 12 within the wellhead 11so as to alter the operating point of the pump assembly 20 along itshead capacity curve and efficiency capacity curve.

These optimization techniques allow for complete control over thetemperature and heat transfer characteristics of the fluids within thecompletion 1. For example, if some degree of tubing fouling occurs suchthat heat transfer is less effective, the pump assembly 20 can beadjusted to re-optimize the thermal behavior of the well 4.Alternatively, as the water cut rises, the Specific Heat (thermalcapacity) of the fluid will change coupled with a possible change influid viscosity. The operation of the well 4 can then be re-optimized byadjusting the pump assembly 20 operating frequency and or operatingpoint of the pump assembly 20 on the head capacity curve.

Multiple Pump Hydrocarbon Completions

It will be appreciated that the above techniques are not limited to theemployment of a single pump system 15. Two multiple pump hydrocarboncompletions will now be described with reference to FIGS. 5, 6 and 7.

FIG. 5 presents a section view of a horizontal reservoir 2 with amultiple pump hydrocarbon completion, as depicted generally by referencenumeral 1 b. The completion 1 b comprises many of the elements describedabove in relation to the single pump completion 1 of FIG. 1 and theseelements are therefore marked with the same reference numerals. However,in the presently described embodiment the single pump system 15 isreplaced by a multiple pump system 37. For ease of understanding, thepresently described embodiment has a multiple pump system 37 thatcomprises two pump modules, 38 a and 38 b. However, it will beappreciated by those skilled in the art that in alternative embodimentsthe number of pump modules 38 employed may be increased and that theactual number employed will depend on the well 4 and reservoir 2characteristics.

Each of the pump modules 38 a and 38 b can be seen to comprise a pumpsystem 15 a and 15 b and a bypass tubing 39 a and 39 b both of which areconnected to an associated electro-hydraulic diverter 40 a and 40 b. Ascan be seen from FIG. 6 the electro-hydraulic diverters 40 a and 40 bcomprise a main tubing 41 and an integrated secondary tubing 42 suchthat it forms a substantially Y-shape. The main tubing comprises a first43 and a second aperture 44 for the diverter 40 while a third aperture45 is provided by the integrated secondary tubing 42.

Each electro-hydraulic diverter 40 further comprises an internal controlvalve 46 that provides a means for selecting between four modes ofoperation for the diverter 40, namely:

-   -   1) the internal control valve 46 is configured such that both        the second 44 and third apertures 45 are open to allow fluid to        flow through;    -   2) the internal control valve 46 is configured such that the        second aperture 44 is sealed to prevent fluid flow while the        third aperture 45 is open to allow fluid flow;    -   3) the internal control valve 46 is configured such that the        third aperture 45 is sealed to prevent fluid flow while the        second aperture 44 is open to allow fluid flow; and    -   4) the internal control valve 46 is configured such that both        the second 44 and third apertures 45 are closed to prevent fluid        to flow through.

With regards to the pump module 38 a the first opening 43 is arranged tobe in fluid communication with the tubing string 7, the second opening44 with the bypass tubing 39 a and the third opening 45 with the pumpsystem 15 a. The arrangement for pump module 38 b, and indeed anyadditional pump modules 38, is similar but for the fact that the firstopening 43 is arranged to be in fluid communication with the bypasstubing 39 a of the previous pump module 38 a.

FIG. 7 presents a section view of a horizontal reservoir 2 with analternative multiple pump hydrocarbon completion, as depicted generallyby reference numeral 1 c. The completion 1 b comprises many of theelements described in relation to the multiple pump hydrocarboncompletion 1 b of FIG. 5 and these elements are marked with the samereference numerals. In this embodiment however the electro-hydraulicdiverter 40 b connects only to pump system 15 b i.e. it does not connectto an associated bypass tubing. Therefore, unlike multiple pumphydrocarbon completion 1 b, multiple pump hydrocarbon completion 1 cdoes not provide a means to allow logging or intervention tools to reachthe bottom of the well 4.

The employment of the electro-hydraulic diverters 40 allow for themultiple pump hydrocarbon completions 1 a and 1 b to operate in a rangeof production modes and well service modes as will now be described infurther detail.

Production Modes

1) Production from Upper Pump System 15 a

In this mode electro-hydraulic diverter 40 a would be configured suchthat that internal control valve 46 a operates in its second mode ofoperation i.e. the second aperture 44 a is sealed while the thirdaperture 45 a is open while the electro-hydraulic diverter 40 b would beconfigured such that that internal control valve 46 b operates in itsfourth mode or operation i.e. both the second 44 b and third apertures45 b are closed to prevent fluid flowing through. Upper pump system 15 awould then be operated in a forward pumping regime.

2) Production from Lower Pump System 15 b

Here electro-hydraulic diverter 40 b would be configured such that thatinternal control valve 46 b operates in its second mode of operationi.e. the second aperture 44 b is sealed while the third aperture 45 b isopen. However, in this production mode the electro-hydraulic diverter 40a would be configured such that that internal control valve 46 aoperates in its third mode of operation i.e. the second aperture 44 a isopen while the third aperture 45 a is sealed to stop re-circulation ofthe production fluid 17. The lower pump system 15 b would then beoperated in a forward pumping regime.

3) Production from Upper & Lower Pump Systems 15 a and 15 b

In this production mode the electro-hydraulic diverter 40 a would beconfigured such that that internal control valve 46 a operates in itsfirst mode of operation i.e. both the second 44 a and third apertures 45a are open to allow fluid to flow through while the electro-hydraulicdiverter 40 b would be configured such that that internal control valve46 b operates in its second mode of operation i.e. the second aperture44 b is sealed while the third aperture 45 b is open. Both the upper 15a and lower 15 b pump systems would then be operated in a forwardpumping regime.

Well Service Modes

1) Reverse Pumping of Production Fluid 17 from Upper Pump System 15 a

In this mode of operation the internal control valve 46 a ofelectro-hydraulic diverter 40 a would be configured to operate in thesecond mode of operation such that the second aperture 44 a is sealed toprevent fluid flow while the third aperture 45 a is open to allow fluidflow. The electro-hydraulic diverter 40 b would be configured such thatthat internal control valve 46 b operates in its fourth mode oroperation i.e. both the second 44 b and third apertures 45 b are closedto prevent fluid flowing through. The upper pump system 15 a would thenbe operated in a reverse pumping regime, which will allow hot producedfluid from tubing string 7 to wash the horizontal well 4.

2) Reverse Pumping of Production Fluid 17 from Lower Pump System 15 b

The internal control valve 46 b of electro-hydraulic diverter 40 b wouldbe configured to operate in the second mode of operation such that thesecond aperture 44 b is sealed to prevent fluid flow while the thirdaperture 45 b is open to allow fluid flow. The electro-hydraulicdiverter 40 a would be configured such that that internal control valve46 a operates in its third mode or operation i.e. the third aperture 45a is sealed to prevent fluid flow while the second aperture 44 a isopen. Lower pump system 15 b would then be operated in a reverse pumpingregime.

It will be appreciated that the above described well service modes couldbe controlled such that alternating between forward and reverse pumpingcould be employed to provide an effective well service program.

3) Circulation of Production Fluid 17 or Stimulation Fluid between Upper& Lower Pump Systems 15 a and 15 b

The internal control valve 46 a of electro-hydraulic diverter 40 a wouldbe configured to operate in the first mode of operation such that boththe second 44 a and third 45 a apertures are open to allow fluid flow.The internal control valve 46 b of electro-hydraulic diverter 40 b wouldbe configured to operate in the second mode of operation such that thesecond aperture 44 b is sealed to prevent fluid flow while the thirdaperture 45 b is open to allow fluid flow. The production choke 12 inthe well head 11 would also be closed so as to allow pump systems 15 aand 15 b to circulate fluid in horizontal well 4 when the upper pumpsystem 15 a is operated in a reverse pumping regime and lower pumpsystem 15 b is operated in a forward pumping regime, or vice versa.

The above methods and apparatus have particular application in improvingthe efficiency of production of heavy and extra heavy oils. Theapparatus may comprise a single pump system or multiple pump system'scombined with ‘intelligent completion’ technology so as to allow for itsuse in a range of production and well servicing modes.

Although not so limited, the described methods and apparatus findparticular application within horizontal, high angle or vertical wellsin heavy or extra heavy oil fields. It is particularly advantageous toarrange these wells to have a long inflow section located within thereservoir.

The completion designs allow for full and optimally efficient use of allof the electrical energy supplied to the well. This energy may be usedto provide hydraulic power to the pumped fluids so as to controllablyincrease the tubing string, wellbore annular and reservoir fluidtemperature. Increasing the fluid temperature substantially reduces theviscosity of the heavy and extra heavy oil, thus reducing the tubingstring and wellbore annular friction.

A direct result of this arrangement is that most of the oil ispre-heated as it flows into the wellbore and alongside the tubing stringtowards the pump intake (whether single or multiple pump embodiments). Ashroud is preferably incorporated within the pump system so as to allowthe hydrocarbon fluid in the annulus 10 to flow past the motor.Therefore heavy and extra heavy oils may achieve a viscosity reductiontypically greater than 95% before they enter the pump intake.

The pre-warmed oil provides a much improved cooling for the pump systemmotor as well as increasing the hydraulic efficiency of the pumpassembly.

It is recognized that the wellbore cross-section area is reduced by thepresence of the tubing string and power cable(s) but this is entirelymitigated by the substantially reduced fluid viscosity of the heavy andextra heavy oil and the reduced effects of wellbore annular and tubularstring friction.

The described completion arrangements also act to minimize thedeposition of wax and other materials within the well. However, in theevent of such deposition the completion designs can be operated ineasily configured modes so as to perform a hot oil or hot water wash onthe inflow sections or a hot well stimulation fluid wash.

The above described multiple pump systems provide a unique capabilityfor selectively producing different parts of the reservoir at differentrates. These systems also provide a unique capability to perform abalanced circulation (i.e. in hydraulic balance, even within a depletedreservoir) for placement of well servicing materials e.g. water shut-offgels, treatment slurries, etc. traditionally these can be problematic todeploy on long horizontal wells (and virtually impossible within heavyand extra heavy oil wells) as the fluid always enters the reservoir atthe heel or the tubing shoe. Accurate ‘placement’ of fluids is thereforenot possible. Utilizing the above described methods and apparatus thepump systems can be used to circulate treatment fluids or slurries to aprecise location by a combination of forward and reverse pumping. Thisoccurs irrespective of depleted reservoir pressure, such that accurateplacement is achieved without hardware intervention.

As a direct consequence of embodiments herein, heavy and extra heavy oilfields can now be developed using efficient and effective longhorizontal wells with full and appropriate inflow and productiondeveloped along the entire length of the horizontal section. Of furtheradvantage is that the completion designs also includes measures to dealwith wax precipitation, emulsions, sand production and other operationalissues without the need for further well intervention.

A method of pumping a hydrocarbon fluid from a wellbore and ahydrocarbon completion implementing the methodology is described. Themethod comprises deploying a tubing string and a first pump systemwithin a wellbore, the first pump system being arranged to be in fluidcommunication with the tubing string. The first pump system is furtherarranged such that a counter current heat exchanger is formed between aproduction fluid pumped by the first pump system within the tubingstring and the hydrocarbon fluid located within the wellbore. Theformation of the counter current heat provides a means for pre-heatingthe hydrocarbon fluid before it reaches the first pump system. As aresult the viscosity of the hydrocarbon fluid is reduced thus making iteasier to pump to the surface. The method finds particular applicationwithin horizontal, high angle or vertical wells in heavy or extra heavyoil fields.

The foregoing description of embodiments of the disclosure has beenpresented for purposes of illustration and description and is notintended to be exhaustive or to limit the embodiments herein to theprecise form disclosed. The described embodiments were chosen anddescribed in order to best explain the principles of the disclosure andits practical application to thereby enable others skilled in the art tobest utilize the disclosure in various embodiments and with variousmodifications as are suited to the particular use contemplated.Therefore, further modifications or improvements may be incorporatedwithout departing from the scope of the disclosure as defined by theappended claims.

What is claimed is:
 1. A system for production of a hydrocarbonaceousfluid, the system comprising: a tubing string deployed within awellbore; a first pump system comprising a pump assembly operablyengaged with a motor, the pump assembly further comprising: a statorcomprising an inner stator surface configured with an one or more statorvanes thereon; a rotor comprising an external stator surface configuredwith an one or more rotor vanes thereon; a housing having the stator andthe rotor disposed therein; wherein a radial gap is provided between theone or more stator vanes and the one or more rotor vanes along a lengthof the pump assembly, wherein a radial length of the one or more rotorvanes is greater than a radial length of the one or more stator vanes,wherein a thickness of the one or more stator vanes is greater than athickness of the one or more rotor vanes, wherein stator channels on theinner stator surface comprise a constant inner diameter, wherein rotorchannels on the rotor outer surface comprise a constant outer diameter,and wherein the first pump system is in fluid communication with thetubing string; and a control system operably engaged with the first pumpsystem; wherein the first pump system is operable to aid in productionof the hydrocarbonaceous fluid from the wellbore to a productionfacility, the hydrocarbonaceous fluid having a viscosity of greater than1,000 cP.
 2. The system of claim 1, wherein the first pump systemfurther comprises a cooling shroud that depends from the pump assemblyso as to define a flow path that requires the hydrocarbon fluid to passover the motor before entering the pump assembly.
 3. The system of claim1, wherein a protector seal module is located between the pump assemblyand the motor.
 4. The system of claim 1, wherein the control system isoperable to change a set of operating parameters of the pump assembly ofso as to optimize the hydrocarbon fluid production from the wellbore,wherein an operating frequency is one of the set of operatingparameters, and wherein the control system is operable to control achoke.
 5. The system of claim 1, the system further comprising a secondpump system like that of the first pump system, the second pump systemalso in fluid communication with the tubing string.
 6. The system ofclaim 1, wherein the hydrocarbonaceous fluid has a viscosity of greaterthan 20,000 cP, and wherein the first pump system is located 75% to 95%of the way along a length of the wellbore.
 7. The system of claim 1,wherein rotor channels and stator channels are all of the same lengthsand cross-sectional area.
 8. The system of claim 1, the pump assemblyfurther comprising: an inlet; an outlet; two bearings separated along anlongitudinal axis of the pump assembly, one of which being proximate tothe inlet, and the other being proximate to the outlet.
 9. A system forproduction of a hydrocarbonaceous fluid, the system comprising: a tubingstring deployed within a wellbore; a first pump system comprising a pumpassembly operably engaged with a motor, the pump assembly furthercomprising: a stator comprising an inner stator surface configured withan at least one stator vane thereon; a rotor comprising an externalstator surface configured with an one or more rotor vanes thereon; ahousing having the stator and the rotor disposed therein; wherein aradial gap is provided between the one or more stator vanes and the oneor more rotor vanes along a length of the pump assembly, wherein aradial length of the one or more rotor vanes is greater than a radiallength of the one or more stator vanes, wherein a thickness of the oneor more stator vanes is greater than a thickness of the one or morerotor vanes, wherein stator channels on the inner stator surfacecomprise a constant inner diameter, wherein rotor channels on the rotorouter surface comprise a constant outer diameter, and wherein the firstpump system is in fluid communication with the tubing string; and acontrol system operably engaged with the first pump system; wherein thefirst pump system is operable to aid in production of ahydrocarbonaceous fluid from the wellbore to a production facility, thehydrocarbonaceous fluid having a viscosity of greater than 1,000 cP. 10.The system of claim 9, wherein the first pump system further comprises acooling shroud that depends from the pump assembly so as to define aflow path that requires the hydrocarbon fluid to pass over the motorbefore entering the pump assembly.
 11. The system of claim 10, wherein aprotector seal module is located between the pump assembly and themotor.
 12. The system of claim 11, wherein the control system isoperable to change a set of operating parameters of the pump assembly ofso as to optimize the hydrocarbon fluid production from the wellbore,wherein an operating frequency is one of the set of operatingparameters, and wherein the control system is operable to control achoke.
 13. The system of claim 12, the system further comprising asecond pump system like that of the first pump system, the second pumpsystem also in fluid communication with the tubing string.
 14. Thesystem of claim 12, wherein the hydrocarbonaceous fluid has a viscosityof greater than 20,000 cP, and wherein the first pump system is located75% to 95% of the way along a length of the wellbore.
 15. The system ofclaim 14, wherein rotor channels and stator channels are all of the samelengths and cross-sectional area.
 16. The system of claim 14, the pumpassembly further comprising: an inlet; an outlet; two bearings separatedalong an longitudinal axis of the pump assembly, one of which beingproximate to the inlet, and the other being proximate to the outlet.